Utilities and Transportation Commission Standard …...Randy Bareither Pipeline Safety Engineer 509-495-8716 Linda Burger Pipeline Integrity Program Manager 509-495-4423 Dylan Karaus

Utilities and Transportation Commission

Standard Inspection Report for Intrastate Gas Distribution Systems

Records Review and Field Inspection – Form C S – Satisfactory U – Unsatisfactory N/A – Not Applicable N/C – Not Checked

If an item is marked U, N/A, or N/C, an explanation must be included in this report.

Form C Intrastate Gas Distribution-Records and Field Insp (Rev. Aug 2013)

A completed Standard Inspection Checklist, OQ Field Validation Protocol form and Cover Letter/Field Report are to be

submitted to the Chief Engineer within 30 days from completion of the inspection.

Inspection Report

Inspection ID/Docket Number 6770

Inspector Name &

Submit Date Lex Vinsel 9/12/2016

Chief Eng Name &

Review/Date Joe Subsits, 9/19/16

Operator Information

Name of Operator: Avista Utilities (Avista) OP ID #: 31232

Name of Unit(s): Spokane

Records Location: Headquarters and Dollar Rd

Date(s) of Last (unit)

Inspection: July 16-25, 2013 Inspection Date(s):

May 17-19, July 12-15, 18-

20, Aug 9, 2016

Inspection Summary:

Field Inspection for unit was done May 17-19, 2016

Records Review for unit was done July 11-15, & 18-20, 2016

DIMP Form 24 completed on August 9, 2016.

16-09-07 – Additional forms required with 6770 Avista District Standard Inspection caused some delays in processing.

Addition of Form 24 to be filled out in the IA program/application from PHMSA.

Addition of form DIMP-GDIM was not anticipated and requires additional time to complete in the IA program/application.

Manuals reviewed were the 2016 versions, Avista republishes all manuals every year.

Manuals Reviewed

Avista 2016 Gas System Management (GSM)

Avista 2016 Gas Emergency System Management (GESH).

Avista 2016 Distribution Integrity Management Plan

Avista 2016 Gas Crew Paperwork Manual

HQ Address: System/Unit Name & Address:

1411 East Mission

PO Box 3727

Spokane, WA 99220-3727

Avista Dollar Road Facility

Spokane WA

Co. Official:

Phone No.:

Fax No.:

Emergency Phone No.:

Heather Rosentrater Phone No.:

Fax No.:

Emergency Phone No.:

Vice President, Director of Natural Gas

None listed

509-495-8499 See Above

Persons Interviewed Title Phone No.






Josh Fort 509-481-0621

Rich Inouye PC Tech 509-994-9652

Bob Larson CP Tech 509-981-4748

Steve Winters CP Tech 509-990-8908

Gary Douglas 509-495-4198

Curt Lystad CP Tech 509-995-1725

Tim Mair Gas Operations Manager - Spokane 509-495-8946

Randy Bareither Pipeline Safety Engineer 509-495-8716

Linda Burger Pipeline Integrity Program Manager 509-495-4423

Dylan Karaus Integrity Management Analyst 509-495-4668

Karen Cash Gas Compliance Manager 509-495-2856

Dawn Donahoo Public Safety Specialist 509-495-2646

Craig Buchanan General Foreman (Spokane Gas) 509-994-9406

Sonia Johnson Sr. Gas Compliance Tech 509-495-4959

Mike Faulkenberry Director Natural Gas 509-495-8499

Darrel Moss Claims Manager 509-435-1909

Jodie Lamp Gas Programs Manager 509-495-2660

WUTC staff conducted an abbreviated procedures inspection on 192 O&M and WAC items that changed since

the last inspection. This checklist focuses on Records and Field items per a routine standard inspection.

(check one below and enter appropriate date) Team inspection was performed (Within the past five years.) or, Date: 4/10-11/2012

Other WUTC Inspector reviewed the O & M Manual (Since the last yearly review of the manual by

the operator.) Date:

OQ Program Review (PHMSA Form 14) Date: Sept 30-Oct 1

2014

GAS SYSTEM OPERATIONS

Gas Supplier Williams and Trans-Canada(GTN)

Services:

Residential 117806 Commercial 11165 Industrial 125 Other 67

Number of reportable safety related conditions last year 0 Number of deferred leaks in system 891

Number of non-reportable safety related conditions last year 0 Number of third party hits last year 155 - 2015

Miles of transmission pipeline within unit (total miles and miles in

class 3 & 4 areas) 25.7, 9.2 Miles Class 3 and None in Class 4.

Miles of main within inspection unit(total miles and miles in class 3 & 4

areas) 3000, 1975 miles in class 3 & 60 in class 4

Operating Pressure(s): MAOP (Within last year) Actual Operating Pressure

(At time of Inspection)

Feeder: Less than 500 psig 500 MAOP 485

Town:

Other:

Does the operator have any transmission pipelines? Yes, they are not part of this audit.

Compressor stations? Use Attachment 1. None in Spokane District






Pipe Specifications:

Year Installed (Range) 1956-Present Pipe Diameters (Range) 0.5 – 24-inch

Material Type Steel and PE plastic Line Pipe Specification

Used API 5L

Mileage 3000 SMYS % Max of 27.3 % at 500 MAOP

Operator Qualification Field Validation

Important: Per OPS, the OQ Field Inspection Protocol Form (Rev 4, May 2007) shall be used by the inspector as part of

this standard inspection. When completed, the inspector will upload this information into the PHMSA OQ Database

(OQDB) located at http://primis.phmsa.dot.gov/oqdb/home.oq Date Completed/Uploaded September 8, 2016

Integrity Management Field Validation

Important: Per PHMSA, IMP Field Verification Form (Rev 6/18/2012) shall be used by the inspector as part of this

standard inspection. When completed, the inspector will upload this information into the PHMSA IM Database (IMDB)

located at http://primis.phmsa.dot.gov/gasimp/home.gim Date Completed/Uploaded: Form Only used during

transmission audit.

PART 199 Drug and Alcohol Testing Regulations and Procedures S U NA NC

Subparts A - C

Drug & Alcohol Testing & Misuse Prevention Program – Use PHMSA Form #13,

Rev 3/19/2010. Do not ask the company to have a drug and alcohol expert available

for this portion of your inspection. X

REPORTING RECORDS S U N/A N/C

1.

49 U.S.C. 60132,

Subsection (b)

For Gas Transmission Pipelines and LNG Plants. Submission of Data to the National

Pipeline Mapping System Under the Pipeline Safety Improvement Act of 2002

Updates to NMPS: Operators are required to make update submissions every 12 months if

any system modifications have occurred. If no modifications have occurred since the last

complete submission (including operator contact information), send an email to

[email protected] stating that fact. Include operator contact information with all

updates.

Submitted 2/26/2016

X

2.

RCW 81.88.080

Pipeline Mapping System: Has the operator provided accurate maps (or updates) of

pipelines, operating over two hundred fifty pounds per square inch gauge, to specifications

developed by the commission sufficient to meet the needs of first responders?

Submitted March 31, 2010.

X

3.

191.5

Immediate Notice of certain incidents to NRC (800) 424-8802, or electronically at

http://www.nrc.uscg.mil/nrchp.html, and additional report if significant new information

becomes available. Operator must have a written procedure for calculating an initial

estimate of the amount of product released in an accident.

One federal reportable during this inspection cycle. 20130050-15833

X

4.

191.7

Reports (except SRCR and offshore pipeline condition reports) must be submitted

electronically to PHMSA at http://portal.phmsa.dot.gov/pipeline at unless an alternative

reporting method is authorized IAW with paragraph (d) of this section.

GESH Section EOP Sheet 8.

X

5.

191.15(a)

30-day follow-up written reports to PHMSA (Form F7100.2) Submittal must be sent

electronically to http://pipelineonlinereporting.phmsa.dot.gov.

One federal reportable during this inspection cycle. 20130050-15833

X

6. 191.15(c)

Supplemental report (to 30-day follow-up)

No supplemental report during this inspection cycle. X

7.

191.17

Complete and submit DOT Form PHMSA F 7100-2.1 by March 15 of each calendar year

for the preceding year. (NOTE: June 15, 2011 for the year 2010).

Submitted on 3/3/2016 to WUTC

X

http://primis.phmsa.dot.gov/oqdb/home.oq

http://www.nrc.uscg.mil/nrchp.html

http://portal.phmsa.dot.gov/pipeline

http://pipelineonlinereporting.phmsa.dot.gov/







8.

191.22

Each operator must obtain an OPID, validate its OPIDs, and notify PHMSA of certain

events at http://portal.phmsa.dot.gov/pipeline.

Avista validated OPID on April 17, 2012.

X

9. 191.23

Filing the Safety Related Condition Report (SRCR)

No SRCR for the district during this timeframe. X

10.

191.25

49 U.S.C. 60139,

Subsection (b)(2)

Filing the SRCR within 5 days of determination, but not later than 10 days after discovery.

Note: Operators of gas transmission pipelines that if the pipeline pressure exceeds

maximum allowable operating pressure (MAOP) plus the build-up, owner/operator must

report the exceedance to PHMSA on or before the fifth day following the date on which

the exceedance occurs.

The report should be titled ‘‘Gas Transmission MAOP Exceedance’’ and provide the

following information:

The name and principal address of the operator date of the report, name, job title,

and business telephone number of the person submitting the report.

The name, job title, and business telephone number of the person who

determined the condition exists.

The date the condition was discovered and the date the condition was first

determined to exist.

The location of the condition, with reference to the town/city/county and state or

offshore site, and as appropriate, nearest street address, offshore platform, survey

station number, milepost, landmark, and the name of the commodity transported

or stored.

The corrective action taken before the report was submitted and the planned

follow-up or future corrective action, including the anticipated schedule for

starting and concluding such action.

No SRCR for the district during this timeframe.

X

11.

.605(d)

Instructions to enable operation and maintenance personnel to recognize potential Safety

Related Conditions

GSM Sec. 4.12 sheet 1, 2.

X

12. 191.27

Offshore pipeline condition reports – filed within 60 days after the inspections

No offshore pipe exists in Spokane district. X

13.

192.727(g)

Abandoned facilities offshore, onshore crossing commercially navigable waterways

reports.

No pipe meeting criteria exists in Spokane district. X

14.

480-93-200(1)

Telephonic Reports to UTC Pipeline Safety Incident Notification 1-888-321-9144

(Within 2 hours) for events which results in;

Reviewed Incident reports for 2015-2013

15. 480-93-200(1)(a)

A fatality or personal injury requiring hospitalization;

None during this time period. X

16.

480-93-200(1)(b)

Damage to property of the operator and others of a combined total exceeding fifty

thousand dollars;

None during this time period.

X

17. 480-93-200(1)(c)

The evacuation of a building, or high occupancy structures or areas;


18. 480-93-200(1)(d)

The unintentional ignition of gas;


19.

480-93-200(1)(e)

The unscheduled interruption of service furnished by any operator to twenty five or more

distribution customers;


X

20.

480-93-200(1)(f)

A pipeline pressure exceeding the MAOP plus ten percent or the maximum pressure

allowed by proximity considerations outlined in WAC 480-93-020; None during this time

period.

X

http://portal.phmsa.dot.gov/pipeline







21.

480-93-200(1)(g)

Is significant, in the judgment of the operator, even though it does not meet the criteria of

(a) through (f) of this subsection;


X

22. 480-93-200(2)

Telephonic Reports to UTC Pipeline Safety Incident Notification 1-888-321-9146

(Within 24 hours) for; Reviewed Incident reports for 2015-2013

23. 480-93-200(2)(a) The uncontrolled release of gas for more than two hours; X

24. 480-93-200(2)(b)

The taking of a high pressure supply or transmission pipeline or a major distribution supply

gas pipeline out of service; None during this time period. X

25. 480-93-200(2)(c)

A gas pipeline operating at low pressure dropping below the safe operating conditions of

attached appliances and gas equipment; or None during this time period. X

26. 480-93-200(2)(d) A gas pipeline pressure exceeding the MAOP X

27. 480-93-200(4)

Did written incident reports (within 30 days of telephonic notice) include the following

Reviewed sample of reports for 2013-2015.

28. 480-93-200(4)(a)

Name(s) and address(es) of any person or persons injured or killed, or whose property was

damaged; X

29. 480-93-200(4)(b) The extent of injuries and damage; X

30.

480-93-200(4)(c)

A description of the incident or hazardous condition including the date, time, and place,

and reason why the incident occurred. If more than one reportable condition arises from a

single incident, each must be included in the report;

X

31. 480-93-200(4)(d)

A description of the gas pipeline involved in the incident or hazardous condition, the

system operating pressure at that time, and the MAOP of the facilities involved; X

32. 480-93-200(4)(e) The date and time the gas pipeline company was first notified of the incident; X

33. 480-93-200(4)(f) The date and time the ((operators')) gas pipeline company's first responders arrived on-site; X

34. 480-93-200(4)(g) The date and time the gas ((facility)) pipeline was made safe; X

35. 480-93-200(4)(h) The date, time, and type of any temporary or permanent repair that was made; X

36. 480-93-200(4)(i) The cost of the incident to the ((operator)) gas pipeline company; X

37. 480-93-200(4)(j) Line type; X

38. 480-93-200(4)(k) City and county of incident; and X

39. 480-93-200(4)(l) Any other information deemed necessary by the commission. X

40.

480-93-200(5)

Supplemental report if required information becomes available after 30 day report

submitted

No supplemental reports during the time period.

X

41.

480-93-200(6)

Written report within 5 days of receiving the failure analysis of any incident or hazardous

condition due to construction defects or material failure

No failure analysis reports during the time period.

X

42. 480-93-200(7)

Filing Reports of Damage to Gas Pipeline Facilities to the commission. (eff 4/1/2013)

(Via the commission’s Virtual DIRT system or on-line damage reporting form)

43. 480-93-200(7)(a)

Does the operator report to the commission the requirements set forth in RCW

19.122.053(3) (a) through (n) X

44.

480-93-200(7)(b)

Does the operator report the name, address, and phone number of the person or entity that

the company has reason to believe may have caused damage due to excavations conducted

without facility locates first being completed? No facility locates are documented.

X

45.

480-93-200(7)(c)

Does the operator retain all damage and damage claim records it creates related to damage

events reported under 93-200(7)(b), including photographs and documentation supporting

the conclusion that a facilities locate was not completed?

Reviewed electronic records and records appear adequate. Note: Records maintained for two years and made available to the commission upon

request.

Damage incident records kept for 6 years

X

46.

480-93-200(8)

Does the operator provide the following information to excavators who damage gas

pipeline facilities?

Notification letter sample included the required material for Items 46-49







47. 480-93-200(8)(a)

Notification requirements for excavators under RCW 19.122.050(1) See Item

46 X

48. 480-93-200(8)(b)

A description of the excavator's responsibilities for reporting damages under

RCW 19.122.053; and See Item 46 X

49.

480-93-200(8)(c) Information concerning the safety committee referenced under RCW 19.122.130,

including committee contact information, and the process for filing a complaint

with the safety committee. See Item 46

X

50.

480-93-200(9)

Reports to the commission only when the operator or its contractor observes or

becomes aware of the following activities…

An excavator digs within thirty-five feet of a transmission pipeline, as defined by

RCW 19.122.020(26) without first obtaining a facilities locate; (200(9)(a) GSM

Spec 4.13 sht 7,8 – None during this time period.

A person intentionally damages or removes marks indicating the location or

presence of gas pipeline facilities. 200(9)(b) - None during this time period.

X

51. 480-93-200(10)

Annual Reports filed with the commission no later than March 15 for the proceeding

calendar year

52. 480-93-200(10)(a)

A copy of PHMSA F-7100.1-1 and F-7100.2-1 annual report required by U.S. Department

of Transportation, PHMSA/Office of Pipeline Safety Submitted on 3/3/2016 X

53.

480-93-200(10)(b)

Reports detailing all construction defects and material failures resulting in leakage.

Categorizing the different types of construction defects and material failures. The report

must include the following:

(i) Types and numbers of construction defects; and

(ii) Types and numbers of material failures. Submitted on 3/3/2016

X

54.

480-93-200(11)

Providing updated emergency contact information to the commission and appropriate

officials of all municipalities where gas pipeline companies have facilities

Provided as required. Reviewed sample

X

55. 480-93-200(12)

Providing by email, reports of daily construction and repair activities no later than 10 AM.

Provided as required. Reviewed sample X

56.

480-93-200(13)

Submitting copy of DOT Drug and Alcohol Testing MIS Data Collection Form when

required.

MIS Data Collection Form submitted with annual report – reviewed sample

X

Comments:

Item 5

30-day follow-up written reports to PHMSA (Form F7100.2) Submittal must be sent electronically

Item 23-40 - Reviewed reports for 2013-2015

CUSTOMER and EXCESS FLOW VALVE INSTALLATION NOTIFICATION S U N/A N/C

57.

192.16

Customer notification - Customers notified, within 90 days, of their responsibility for

those service lines not maintained by the operator.

GSM 4.22 reviewed new customer package

X

58. 192.381

Does the excess flow valve meet the performance standards prescribed under §192.381?

Reviewed excess flow valve tech sheet. X

59.

192.383

Does the operator have an installation and reporting program for excess flow valves and

does the program meet the requirements outlined in §192.383? Are records adequate?

GSM spec 3.16 sht 1, 2 – Records appear adequate.

X

Comments:






CONSTRUCTION RECORDS S U N/A N/C

60. 480-93-013

OQ records for personnel performing New Construction covered tasks

GSM Spec 4.31 sht 3 – Reviewed records for service man. X

61.

192.225

Test Results to Qualify Welding Procedures

GSM Section 3.22 Appendix A Reviewed test results for a sample of welding

procedures.

X

62. 192.227

Welder Qualification

GSM Spec 3.22 sht 1 X

63. 480-93-080(1)(b)

Appendix C Welders re-qualified 2/Yr (7.5Months)

No appendix C welders X

64. 480-93-080(2)

Plastic pipe joiners re-qualified 1/Yr (15 Months)

GSM Spec 3.23 sht 1 – Avista tracks production joining. X

65. 480-93-080(2)(b)

Plastic pipe joiners re-qualified if no production joints made during any 12 month period

GSM Spec 3.23 sht 1 – Avista tracks production joining. X

66. 480-93-080(2)(c)

Tracking Production Joints or Re-qualify joiners 1/Yr (12Months)

Spec 3.23 sht 1 – Avista tracks production joining. X

67. 480-93-115(2)

Test leads on casings (without vents) installed after 9/05/1992.


68. 480-93-115(3)

Sealing ends of casings or conduits on transmission lines and mains


69. 480-93-115(4)

Sealing ends (nearest building wall) of casings or conduits on services.


70. 192.241(a)

Visual Weld Inspector Training/Experience

OQ Task 221.130.005 Reviewed visual weld inspection certification. X

71. 192.243(b)(2)

Nondestructive Technician Qualification

No transmission welding during this inspection. X

72. 192.243(c)

NDT procedures joining


73. 192.243(f)

Total Number of Girth Welds


74. 192.243(f)

Number of Welds Inspected by NDT


75. 192.243(f)

Number of Welds Rejected


76. 192.243(f)

Disposition of each Weld Rejected


77. .273/.283

Qualified Joining Procedures Including Test Results

GSM Spec 3.23 sht 2, Spec 3.24 sht 1, Spec 3.25 sht 1 X

78.

192.303

Construction Specifications.

Spec 3.18 sht 10 – Avista declares that all construction complied with current

company standards on Form N-2490 (Pressure Test Information)

X

79. 192.325

WAC 480-93-

178(4)(5)

Underground Clearances

Spec 3.18 sht 10 – Avista declares that all construction complied with current

company standards on Form N-2490 (Pressure Test Information)

X

80. 192.327

Amount, location, cover of each size of pipe installed.

Depth of cover and location of pipe on as built drawings. X






CONSTRUCTION RECORDS S U N/A N/C

81.

480-93-160(1)

Report filed 45 days prior to construction or replacement of transmission pipelines ≥ 100

feet in length

Reviewed records of transmission pipeline over 100 ft.(1)

X

82.

480-93-160(2)

Did report describe the proposed route and the specifications for the pipeline and must

include, but is not limited to the following items:

No transmission pipeline during this inspection.

X

83. 480-93-160(2)(a)

Description and purpose of the proposed pipeline;

No transmission pipeline during this inspection. X

84.

480-93-160(2)(b)

Route map showing the type of construction to be used throughout the length of the line,

and delineation of class location as defined in 49 CFR Part 192.5, and incorporated

boundaries along the route.


X

85.

480-93-160(2)(c)

Location and specification of principal valves, regulators, and other auxiliary equipment

to be installed as a part of the pipeline system to be constructed


X

86. 480-93-160(2)(d)

MAOP for the gas pipeline being constructed;


87.

480-93-160(2)(e)

Location and construction details of all river crossings or other unusual construction

requirements encountered en route.


X

88.

480-93-160(2)(f)

Proposed corrosion control program to be followed inc specs for coating and wrapping,

and method to ensure the integrity of the coating using holiday detection equipment;


X

89. 480-93-160(2)(g)

Welding specifications; and


90. 480-93-160(2)(h)

Bending procedures to be followed if needed.


91.

480-93-170(1)

Commission notified 2 days prior to pressure testing pipelines with an MAOP producing

a hoop stress ≥ 20% SMYS?


X

92.

480-93-170(7)

Pressure tests records at a minimum include required information listed under 480-93-

170(a-h)

Avista Test Pressure forms include all required information.

X

93.

480-93-170(9)

Individual pressure test records maintained for single installations where multiple

pressure tests were performed?

Reviewed individual pressure tests during review of as-builds.

X

94.

480-93-170(10)

Pressure Testing Equipment checked for accuracy/intervals (Manufacturers Rec or

Operators schedule).

GSM Spec 5.21 Reviewed equipment maintenance during field portion.

X

95.

480-93-175(2)

Study prepared and approved prior to moving and lowering of metallic pipelines > 60

psig and greater than 2-inch diameter.

GSM Spec 3.12 sht 10, 11 – none during this time period.

X

96.

480-93-175(4)

Leak survey within 30 days of moving or lowering pipelines ≤ 60 psig and 2-inches or

smaller.

Spec 3.12 sht 11 – none during this time period.

X

Comments:

Item 96 – Add underlined text as shown - Leak survey within 30 days of moving or lowering pipelines ≤ 60 psig and 2-inches or smaller.






OPERATIONS and MAINTENANCE RECORDS S U N/A N/C

97. 192.517(a)

Pressure Testing (operates at or above 100 psig) – useful life of pipeline

Reviewed high pressure jobs for time period. X

98. 192.517(b)

Pressure Testing (operates below 100 psig, service lines, plastic lines) – 5 years

Reviewed as builds for pressure test notation sample for 2013-2015. X

99.

192.605(a)

Procedural Manual Review – Operations and Maintenance (1 per yr/15 months)

Note: Including review of OQ procedures as suggested by PHMSA - ADB-09-03 dated

2/7/09

Reviewed SPEC 4.31 and examples of OQ task sheets.

X

100.

192.605(b)(3)

Availability of construction records, maps, operating history to operating personnel.

Personnel have access to records and maps through the GO Books that the service

people carry.

X

101.

480-93-018(3)

Records, including maps and drawings updated within 6 months of completion of

construction activity?

Reviewed sample of work orders and were mapped within 6 month period.

X

102. 192.605(b)(8)

Periodic review of personnel work – effectiveness of normal O&M procedures

QA/QC – GESH EOP Sheet 1 Procedures reviewed annually. X

103.

192.605(c)(4)

Periodic review of personnel work – effectiveness of abnormal operation procedures

Management review of trouble orders reviewed 20 of 449 code 5 and 20 of 2400

records reviewed. Procedure GESH section 1 sht 6.

X

104. 192.609 Class Location Study (If applicable) GSM Spec 4.16 shts 2,3,4 X

105. 192.611 Confirmation or revision of MAOP GSM Spec 4.16 shts 3,4 X

106.

192.614

Damage Prevention (Operator Internal Performance Measures)

107. Does the operator have a quality assurance program in place for monitoring the locating

and marking of facilities? Do operators conduct regular field audits of the performance

of locators/contractors and take action when necessary? (CGA Best Practices v. 6.0, Best

Practice 4-18. Recommended only, not required)

QA/QC program and ELM contractors interval quality processes. Reviewed

quarterly report for ELM.

X

108. Does operator including performance measures in facility locating services contracts

with corresponding and meaningful incentives and penalties?

Included in the general services section of the contract.

X

109. Do locate contractors address performance problems for persons performing locating

services through mechanisms such as re-training, process change, or changes in staffing

levels?

ELM (contractor) has increasing discipline policy for bad location performance.

Three strikes and you are out.

X

110. Does the operator periodically review the Operator Qualification plan criteria and

methods used to qualify personnel to perform locates?

OQ program part of standards Section 4.31 is reviewed during regular annual

review.

X

111. Review operator locating and excavation procedures for compliance with state law and

regulations.

SPEC 4.13 – Damage Prevention Program is compliant with State law and

regulations.

X

112. Are locates are being made within the timeframes required by state law and regulations?

Examine record sample.

Locates appear to be made within the two business days.

X

113. Are locating and excavating personnel properly qualified in accordance with the

operator’s Operator Qualification plan and with federal and state requirements?

Reviewed a sample OQ certification for ELM locators.

X






OPERATIONS and MAINTENANCE RECORDS S U N/A N/C

114. Follow-up inspection performed on the pipeline where there is reason to believe the

pipeline could be damaged .614(c) (6)

1. Is the inspection the done as frequently as necessary during and after the

activities to verify the integrity of the pipeline?

Spec 4.13 sheet 4

2. In the case of blasting, does the inspection include leakage surveys?

Spec 4.13 sheet 5

X

Comments:

115. Emergency Response Plans S U N/A N/C

116.

192.603(b)

Prompt and effective response to each type of emergency .615(a)(3)

Note: Review operator records of previous accidents and failures including third-party

damage and leak response.



X

117. 192.615(b)(1)

Location Specific Emergency Plan.

Reviewed site specific Emergency plan and appears to be adequate. X

118.

192.615(b)(2)

Emergency Procedure training, verify effectiveness of training.

Emergency procedures are included in OQ tasks – Review mock drills sponsored

by Avista and manager training outline.

X

119.

192.615(b)(3)

Employee Emergency activity review, determine if procedures were followed.



X

120.

192.615(c)

Liaison Program with Public Officials

Reviewed records of 54 out of 86 visits for 2015 of police, fire, and other public

officials.

X

121. 192.616 Public Awareness Program

122.

192.616(e&f)

Documentation properly and adequately reflects implementation of operator’s Public

Awareness Program requirements - Stakeholder Audience identification, message type

and content, delivery method and frequency, supplemental enhancements, program

evaluations, etc. (i.e. contact or mailing rosters, postage receipts, return receipts,

audience contact documentation, etc. for emergency responder, public officials, school

superintendents, program evaluations, etc.). See table below:

Reviewed materials for different stakeholder audiences and the delivery

timeframes. Also reviewed monthly flier that includes one of the two annual

messages for LDC customers.

X

123.

Operators in existence on June 20, 2005, must have completed their written programs no

later than June 20, 2006. See 192.616(a) and (j) for exceptions.

Program initiated within timeframe.

124. API RP 1162 Baseline* Recommended Message Deliveries






125.

Stakeholder Audience (LDC’s) Baseline Message Frequency

(starting from effective date of Plan)

Residence Along Local Distribution

System

Annual

LDC Customers Twice annually

One-Call Centers As required of One-Call Center

Emergency Officials Annual

Public Officials 3 years

Excavator and Contractors Annual

Stakeholder Audience (Transmission

line operators)

Baseline Message Frequency

(starting from effective date of Plan)

Residence Along Local Distribution

System

2 years

One-Call Centers As required of One-Call Center

Emergency Officials Annual

Public Officials 3 years

Excavator and Contractors Annual

126.

* Refer to API RP 1162 for additional requirements, including general program

recommendations, supplemental requirements, recordkeeping, program evaluation, etc.

127.

192.616(g)

The program conducted in English and any other languages commonly understood by a

significant number of the population in the operator's area.

Avista also provides materials in Spanish in areas of high percentage of Spanish

speakers.

X

128.

.616(h)

IAW API RP 1162, the operator’s program should be reviewed for effectiveness within

four years of the date the operator’s program was first completed. For operators in

existence on June 20, 2005, who must have completed their written programs no later

than June 20, 2006, the first evaluation is due no later than June 20, 2010. .616(h)

Initial effectiveness review completed by June 20, 2010. Avista plans to repeat in

2017.

X

129.

192.616(j)

Operators of a Master Meter or petroleum gas system – public awareness messages 2

times annually:

(1) A description of the purpose and reliability of the pipeline;

(2) An overview of the hazards of the pipeline and prevention measures used;

(3) Information about damage prevention;

(4) How to recognize and respond to a leak; and

(5) How to get additional information.

Avista is not a master meter operator.

X

130.

192.617

Review operator records of accidents and failures including laboratory analysis where

appropriate to determine cause and prevention of recurrence .617 Note: Including

excavation damage and leak response records (PHMSA area of emphasis) (NTSB B.10)

GSM Spec 4.31 shts 6, 7. – Accident reports are reviewed by Avista staff.

X

Comments:






131.

192.619/621/623

Maximum Allowable Operating Pressure (MAOP)

Note: New PA-11 design criteria is incorporated into 192.121 & .123 (Final Rule Pub.

12/24/08)

GSM Spec 4.15 shts 1-3 – Avista does not use PA-11 pipe.

X

132. 480-93-015(1)

Odorization of Gas – Concentrations adequate

Minimum concentration for Avista is 0.4% gas. X

133.

480-93-015(2)

Monthly Odorant Sniff Testing

GSM Spec 4.31 shts 6, 7. – Accident reports are reviewed by Avista staff.

Reviewed the monthly reads for 2013-2015.

X

134.

480-93-015(3)

Prompt action taken to investigate and remediate odorant concentrations not meeting the

minimum requirements.

Retests are done immediately if initial read greater than 0.4%.

X

135.

480-93-015(4)

Odorant Testing Equipment Calibration/Intervals (Annually or Manufacturers

Recommendation)

Reviewed calibration for instruments.

X

136. 480-93-124(3)

Pipeline markers attached to bridges or other spans inspected? 1/yr(15 months)

Reviewed patrol records for 2013-2015. Avista does bridge patrols quarterly. X

137. 480-93-124(4)

Markers reported missing or damaged replaced within 45 days?

Markers replaced immediately. X

138. 480-93-140(2)

Service regulators and associated safety devices tested during initial turn-on

GESH Section 6 sht 6. X

139.

480-93-155(1)

Up-rating of system MAOP to >60 psig? Procedures and specifications submitted 45

days prior?

No uprates in Spokane system during this time period.

X

140.

480-93-185(1)

Reported gas leaks promptly investigated? Graded in accordance with 480-93-186?

Records retained?

Reviewed records appear to be adequate.

X

141.

480-93-185(3)(a)

Leaks originating from a foreign source. Take appropriate action to protect life and

property regarding the pipeline company’s own facilities, and;

GSM Spec 5.11 sht 5

X

142.

480-93-185(3)(b)

Leaks originating from a foreign source reported promptly/notification by mail. Records

retained?

Reviewed letters as notification of gas originating from foreign source.

X

143. 480-93-186(3)

Leak evaluations: Are follow-up inspections performed within 30 days of a leak repair?

Follow-up inspections performed within 30 days. X

144.

480-93-186(4)

Leak evaluations: Grade 1 and 2 leaks (if any), downgraded once to a grade 3 without

physical repair?

Spec 5.11 sht 16

X

145.

480-93-187

Gas leak records: at a minimum include required information listed under 480-93-187(1-

13)

Required information is found on records.

X

146. 480-93-188(1)

Gas leak surveys

GSM 5.11 Sht 3 X

147.

480-93-188(2)

Gas detection instruments tested for accuracy/intervals (Mfct recommended or monthly

not to exceed 45 days)

FI instruments are calibrated daily.

X

148. 480-93-188(3)

Leak survey frequency (Refer to Table Below)

SPEC 5.11 sht 6,7 X

Business Districts (implement by 6/02/07) 1/yr (15 months)

High Occupancy Structures 1/yr (15 months)

Pipelines Operating ≥ 250 psig 1/yr (15 months)

Other Mains: CI, WI, copper, unprotected steel 2/yr (7.5 months)

149.

480-93-188(4)(a)

Special leak surveys - Prior to paving or resurfacing, following street alterations or

repairs

GSM Spec 5.11 sht 7,8.- Reviewed records for 2013-2015.

X






150.

480-93-188(4)(b)

Special leak surveys - areas where substructure construction occurs adjacent to

underground gas facilities, and damage could have occurred.

GSM Spec 5.11 sht 7,8 - Reviewed records for 2013-2015

X

151. 480-93-188(4)(c)

Special leak surveys - Unstable soil areas where active gas lines could be affected.

GSM Spec 5.11 sht 7,8 - Reviewed records for 2013-2015 X

152. 480-93-188(4)(d)

Special leak surveys - areas and at times of unusual activity, such as earthquake, floods,

and explosions GSM Spec 5.11 sht 7,8.- Reviewed records for 2013-2015 X

153.

480-93-188(4)(e)

Special leak surveys - After third-party excavation damage to services, operators must

perform a gas leak survey to eliminate the possibility of multiple leaks and underground

migration into nearby buildings.

GSM Spec 5.11 sht 7,8 - Reviewed records for 2013-2015

X

154.

480-93-188(5)

Gas Survey Records (Min 5 yrs) and at a minimum include required information listed

under 480-93-188 (5) (a-f).

Survey records contain required information.

X

155. 480-93-188(6)

Leak program - Self Audits.

GSM Spec 5.11 sht 16 reviewed self-audits for 2013, 2014, 2015 X

156. 192.709

Patrolling (Transmission Lines) (Refer to Table Below).705

Transmission records not reviewed during this inspection. X

Class Location At Highway and Railroad Crossings At All Other Places

1 and 2 2/yr (7½ months) 1/yr (15 months)

3 4/yr (4½ months) 2/yr (7½ months)

4 4/yr (4½ months) 4/yr (4½ months)

157. 192.709 Leak Surveys (Transmission Lines) (Refer to Table Below) .706


Class Location Required Not Exceed

1 and 2 1/yr 15 months

3 2/yr 7½ months

4 4/yr 4½ months

158. 192.603(b) Patrolling Business District (4 per yr/4½ months) .721(b)(1)

Reviewed bridge patrols for 2013-2015 X

159. 192.603(b) Patrolling Outside Business District (2 per yr/7½ months) 192.721(b)(2)

All inspected 4 times per year. Reviewed bridge patrols for 2013-2015 X

160. 192.603(b) Leakage Survey - Outside Business District (5 years) 192 .723(b)(1)

Reviewed leakage survey leaks for 2013(10/467), 2014(30/2499), 2015(24/1903) X

161.

192.603(b)

Leakage Survey 192.723(b)(2)

Outside Business District (5 years)

Cathodically unprotected distribution lines (3 years)

Reviewed leakage survey leaks for 2013(10/467), 2014(30/2499), 2015(24/1903)

X

162. 192.603(b) Tests for Reinstating Service Lines 192.725

GSM Spec 5.17 – Reviewed as-builts for 2013-2015. X

163. 192.603(b)/.727(g) Abandoned Pipelines; Underwater Facility Reports 192.727

None in district X

164. 192.709 Pressure Limiting and Regulating Stations (1 per yr/15 months) .739

Reviewed 20 out of 93 random samples and records appear adequate. X

165. 192.709 Pressure Limiting and Regulator Stations – Capacity (1 per yr/15 months) .743

Reviewed sample of Relief Capacity Review. X

166. 192.709 Valve Maintenance – Transmission (1 per yr/15 months) .745

No transmission records this inspection. X

167. 192.709 Valve Maintenance – Distribution (1 per yr/15 months) .747

Reviewed 30 out of 1200 records for valve maintenance for 2013-2015. X

168. 480-93-100(3) Service valve maintenance (1 per yr/15 months)

Reviewed emergency curb valve records. Valves are inspected annually X






169. 192.709 Vault maintenance (200 cubic feet)(1 per yr/15 months) .749

No vaults in Washington X

170. 192. 603(b) Prevention of Accidental Ignition (hot work permits) .751

GSM Spec 3.17 sht 1 – reviewed Form N-2651. X

171. 192. 603(b) Welding – Procedure 192.225(b)

Reviewed welding procedures. See Item 61 X

172. 192. 603(b) Welding – Welder Qualification 192.227/.229

Welders requalify every 6 months. Reviewed Weld Quals for 2013-2015 X

173. 192. 603(b) NDT – NDT Personnel Qualification .243(b)(2)

Transmission not reviewed during this inspection. X

174. 192.709 NDT Records (pipeline life) .243(f)


175. 192.709 Repair: pipe (pipeline life); Other than pipe (5 years)


176. 192.905(c) Periodically examining their transmission line routes for the appearance of newly

identified area’s (HCA’s)

Transmission records not reviewed during this inspection.

X

Comments:

Item 154

Gas Survey Records (Min 5 yrs)

Gas Survey Records (Min 5 yrs) and at a minimum include

CORROSION CONTROL RECORDS S U N/A N/C

177.

192.455(a)(1)

Pipeline coatings meet requirements of 192.461 (for buried pipelines installed after

7/31/71)

GSM spec 3.12 sht 4,5. & spec 2.32 sht 5. Materials meet requirements.

X

178.

192.455(a)(2)

CP system installed on and operating within 1 yr of completion of pipeline construction

(after 7/31/71)

GSM Section Spec 2.32 Page 5

X

179.

192.465(a)

Annual Pipe-to-soil Monitoring (1 per yr/15 months) for short sections (10% per year;

all in 10 years)

Reviewed number of short sections for 2013-2015 and Avista is inspecting or

removing at least 10% per year.

X

180. 192.491

Test Lead Maintenance .471.

Spec 2.32 sht 6 X

181. 192.491

Maps or Records .491(a)

Reviewed maps and they appear adequate. X

182.

192.491

Examination of Buried Pipe when exposed .459

Reviewed exposed pipe reports and reviewed follow-up reports of exposed pipe

reports. Spec 3.44 sht 1

X

183. 480-93-110(8)

CP test reading on all exposed facilities where coating has been removed.

Reviewed exposed pipe reports and follow up reports – random sample. X

184. 192.491

Annual Pipe-to-soil monitoring (1 per yr/15 months) .465(a)

Reviewed annual reads and drilled down on a few work orders. X

185.

192.491

Rectifier Monitoring (6 per yr/2½ months) .465(b)

Reviewed Rectifier readings for 2013-2915 and picked samples of 4-5 readings to

drill down.

X

186. 192.491

Interference Bond Monitoring – Critical (6 per yr/2½ months) .465(c)

Reviewed critical bond for 2013-2015, one site. X






CORROSION CONTROL RECORDS S U N/A N/C

187. 192.491

Interference Bond Monitoring – Non-critical (1 per yr/15 months) .465(c)

No non critical bonds in system. X

188.

480-93-110(2)

Remedial action taken within 90 days (Up to 30 additional days if other circumstances.

Must document) .465(d)

Reviewed the CP follow-up CP work orders. 2013-2015.

X

189.

480-93-110(3)

CP equipment/ instrumentation maintained, tested for accuracy, calibrated, and

operated in accordance with manufactures recommendations, or at appropriate schedule

determined by gas company if no recommendation.

Reviewed calibration records for 2013-2015.

X

190.

192.491

Unprotected Pipeline Surveys, CP active corrosion areas (1 per 3 cal yr/39 months)

.465(e)

No unprotected pipe in Spokane district

X

191. 192.491

Electrical Isolation (Including Casings) .467

Reviewed casing records 2013-2015 X

192. 480-93-110(5)

Casings inspected/tested annually not to exceed fifteen months

Reviewed casing records 2013-2015 X

193.

480-93-110(5)(a)

Casings w/no test leads installed prior to 9/05/1992. Demonstrate other acceptable test

methods

Spec 5.14 shts 11-12

X

194.

480-93-110(5)(b)

Possible shorted conditions – Perform confirmatory follow-up inspection within 90

days

GSM Section 5.14 sht 4-5, no additional shorted casings during this time period.

X

195. 480-93-110(5)(c)

Casing shorts cleared when practical

Shorted casings are being monitored and are cleared when possible. X

196.

480-93-110(5)(d)

Shorted conditions leak surveyed within 90 days of discovery. Twice annually/7.5

months

GSM Spec 5.11 sht 8

X

197. 192.491

Interference Currents .473

Operator does not have knowledge of stray currents having any detrimental effects. X

198. 192.491

Internal Corrosion; Corrosive Gas Investigation .475(a)

Avista has non corrosive gas by contract. X

199. 192.491

Internal Corrosion; Internal Surface Inspection; Pipe Replacement .475(b)

Reviewed exposed pipe reports for internal inspection of exposed pipe. X

200. 192.491

Internal Corrosion Control Coupon Monitoring (2 per yr/7½ months) .477

No coupons - Avista has non corrosive gas by contract. X

201.

192.491

Atmospheric Corrosion Control Monitoring (1 per 3 cal yr/39 months onshore; 1 per

yr/15 months offshore) .481

Reviewed 16 out of 224 records of atmospheric corrosion that were detected during

the Atmospheric corrosion inspections.

X

202.

192.491

Remedial: Replaced or Repaired Pipe; coated and protected; corrosion evaluation and

actions .483/.485

GSM Sec 2.32 sht 5, remediated within 90 days

X

Comments:

Gas Standards Manual - GSM Section Spec 2.32 Page 5

PIPELINE INSPECTION (Field) S U N/A N/C

203. 192.161 Supports and anchors X

204. 480-93-080(1)(d)

Welding procedures located on site where welding is performed?

Welding not observed during Field Inspection. X

205. 480-93-080(1)(b) Use of testing equipment to record and document essential variables. X







Welding not observed during Field Inspection.

206. 480-93-080(2)(a)

Plastic procedures located on site where welding fusion is performed?

No fusion observed during Field portion of inspection. X

207.

480-93-080(3)

Identification and qualification cards/certificates w/name of welder/joiner, their

qualifications, date of qualification and operator whose qualification procedures were

followed.

X

208. 480-93-013

Personnel performing “New Construction” covered tasks OQ qualified?

No New Construction observed during Field portion of inspection. X

209. 480-93-015(1) Odorization X

210. 480-93-018(3)

Updated records, inc maps and drawings made available to appropriate operations

personnel? X

211. 192.179 Valve Protection from Tampering or Damage X

212.

192.455

Pipeline coatings meet requirements of 192.461 (for buried pipelines installed after

7/31/71)

No coating observed during Field portion of inspection.

X

213. 192.463 Levels of cathodic protection X

214. 192.465 Rectifiers X

215. 192.467 CP - Electrical Isolation - Casings X

216. 192.476

Systems designed to reduce internal corrosion

Avista only transports dry natural gas. X

217. 192.479 Pipeline Components exposed to the atmosphere X

218. 192.481 Atmospheric Corrosion: monitoring X

219. 192.491 Test Stations – Sufficient Number .469 X

220. 480-93-115(2) Casings – Test Leads (casings w/o vents installed after 9/05/1992) X

221. 480-93-115(2)

Mains or transmission lines installed in casings/conduit. Are casing ends sealed?

No casing ends inspected during Field portion. X

222.

480-93-115(4)

Service lines installed in casings/conduit. Are casing ends nearest to building walls

sealed?

No casing installs observed during Field portion of inspection.

X

223. 192.605(a)

Appropriate parts of manuals kept at locations where O&M activities are conducted

Manuals are available to personnel. X

224. 192.605 Knowledge of Operating Personnel X

225. 480-93-124 Pipeline markers X

226. 480-93-124(4)

Markers reported missing or damaged replaced within 45 days?

No Markers reported missing or damaged during Field portion of inspection. X

227. 192.719 Pre-pressure Tested Pipe (Markings and Inventory) NONE X

228. 192.195 Overpressure protection designed and installed where required? X

229. 192.739/743 Pressure Limiting and Regulating Devices (Mechanical/Capacities) X

230. 192.741 Telemetering, Recording Gauges X

231. 192.751 Warning Signs X

232.

192.355

Customer meters and regulators. Protection from damage

No customer (service) meters or regulators inspected during Field portion of

inspection.

X

233. 192.355(c)

Pits and vaults: Able to support vehicular traffic where anticipated.

No pits or vaults in Spokane district. X

234.

480-93-140

Service regulators installed, operated and maintained per state/fed regs and

manufacturers recommended practices?

No customer (service) meters or regulators inspected during Field portion of

inspection.

X

235. 480-93-178(2) Plastic Pipe Storage facilities – Maximum Exposure to Ultraviolet Light (2yrs) (3years) X







236.

480-93-178(4)

Minimum Clearances from other utilities. For parallel lines a minimum of twelve inches.

Where a minimum twelve inches of separation is not possible, must take adequate

precautions, such as inserting the plastic pipeline in conduit, to minimize any potential

hazards.

No clearances from other utilities inspected during Field portion.

X

237.

480-93-178(5)

Minimum Clearances from other utilities. For perpendicular lines a minimum of six

inches of separation from the other utilities. Where a minimum six inches of

separation is not possible, must take adequate precautions, such as inserting the plastic

pipeline in conduit, to minimize any potential hazards.

No clearances from other utilities inspected during Field portion.

X

238. 480-93-178(6) Are there Temporary above ground PE pipe installations currently? Yes No X

239. 480-93-178(6)(a)

If yes, is facility monitored and protected from potential damage?

No Temporary above ground PE during inspection. X

240.

480-93-178(6)(b)

If installation exceeded 30 days, was commission staff notified prior to exceeding the

deadline?

No Temporary above ground PE during inspection.

X

241. 192.745

Valve Maintenance (Transmission)


242. 192.747 Valve Maintenance (Distribution) X

Facility Sites Visited:

Facility Type Facility ID Number Location

See comments below

Comments:

Facility Types and Locations visited during Field portion are recorded on Form R. See form R in Document Library.

Item 235

Maximum Exposure to Ultraviolet Light (2yrs) (3years)

Recent Gas Pipeline Safety Advisory Bulletins: (Last 2 years)

Number Date Subject






ADB-2013-07 July 12, 13 Potential for Damage to Pipeline Facilities Caused by Flooding

ADB-2012-10 Dec 5, 12 Using Meaningful Metrics in Conducting Integrity Management Program Evaluations

ADB-2012-09 Oct 11, 12 Communication During Emergency Situations

ADB-2012-08 Jul 31, 12 Inspection and Protection of Pipeline Facilities After Railway Accidents

ADB-12-07 Jun 11, 12 Mechanical Fitting Failure Reports

ADB-12-06 May 7, 12 Verification of Records establishing MAOP and MOP

ADB-12-05 Mar 23, 12 Cast Iron Pipe (Supplementary Advisory Bulletin)

ADB -12-04 Mar 21, 12 Implementation of the National Registry of Pipeline and Liquefied Natural Gas Operators

ADB-12-03 Mar 6, 12 Notice to Operators of Driscopipe 8000 High Density Polyethylene Pipe of the Potential for

Material Degradation

ADB-11-05 Sep 1, 11 Potential for Damage to Pipeline Facilities Caused by the Passage of Hurricanes

For more PHMSA Advisory Bulletins, go to http://phmsa.dot.gov/pipeline/regs/advisory-bulletin

http://phmsa.dot.gov/pipeline/regs/advisory-bulletin

Attachment 1

Distribution Operator Compressor Station Inspection Unless otherwise noted, all code references are to 49CFR Part 192. S – Satisfactory U – Unsatisfactory N/A – Not Applicable N/C – Not Checked



243. .605(b)

COMPRESSOR STATION PROCEDURES

No Compressor Stations in Spokane District. S U N/A N/C

244. .605(b)(6) Maintenance procedures, including provisions for isolating units or sections of

pipe and for purging before returning to service X

245. .605(b)(7) Starting, operating, and shutdown procedures for gas compressor units X

246. .731 Inspection and testing procedures for remote control shutdowns and pressure

relieving devices (1 per yr/15 months), prompt repair or replacement X

247. .735 (a) Storage of excess flammable or combustible materials at a safe distance

from the compressor buildings X

248. (b) Tank must be protected according to NFPA #30 X

249. .736 Compressor buildings in a compressor station must have fixed gas detection and

alarm systems (must be performance tested), unless: X

250. 50% of the upright side areas are permanently open, or X

251. It is an unattended field compressor station of 1000 hp or less X

Comments:

No Compressor Stations in Spokane District.

COMPRESSOR STATION O&M PERFORMANCE AND RECORDS

No Compressor Stations in Spokane District. S U N/A N/C

252. .709 .731(a) Compressor Station Relief Devices (1 per yr/15 months) X

253. .731(c) Compressor Station Emergency Shutdown (1 per yr/15 months) X

254. .736(c) Compressor Stations – Detection and Alarms (Performance Test) X

Comments:


COMPRESSOR STATIONS INSPECTION (Field)

(Note: Facilities may be “Grandfathered”)


S U N/A N/C

255. .163 (c) Main operating floor must have (at least) two (2) separate and unobstructed exits X

256. Door latch must open from inside without a key X

257. Doors must swing outward X

258. (d)

Each fence around a compressor station must have (at least) 2 gates or other facilities for

emergency exit X

259. Each gate located within 200 ft of any compressor plant building must open outward X

260. When occupied, the door must be opened from the inside without a key X

261. (e)

Does the equipment and wiring within compressor stations conform to the National Electric

Code, ANSI/NFPA 70? X

262. .165 (a) If applicable, are there liquid separator(s) on the intake to the compressors? X

Attachment 1







S U N/A N/C

263. (b) Do the liquid separators have a manual means of removing liquids? X

264.

If slugs of liquid could be carried into the compressors, are there automatic dumps on the

separators, Automatic compressor shutdown devices, or high liquid level alarms? X

265. .167 (a) ESD system must:

266. - Discharge blowdown gas to a safe location X

267. - Block and blow down the gas in the station X

268.

- Shut down gas compressing equipment, gas fires, electrical facilities in compressor building

and near

gas headers

X

269.

- Maintain necessary electrical circuits for emergency lighting and circuits needed to protect

equipment from damage X

270. ESD system must be operable from at least two locations, each of which is:

271. .167 - Outside the gas area of the station X

272. - Not more than 500 feet from the limits of the station X

273. - ESD switches near emergency exits? X

274. (b) For stations supplying gas directly to distribution systems, is the ESD system configured so

that the LDC will not be shut down if the ESD is activated? X

275. (c) Are ESDs on platforms designed to actuate automatically by…

276. - For unattended compressor stations, when:

277. ▪ The gas pressure equals MAOP plus 15%? X

278. ▪ An uncontrolled fire occurs on the platform? X

279. - For compressor station in a building, when

280. ▪ An uncontrolled fire occurs in the building? X

281.

▪ Gas in air reaches 50% or more of LEL in a building with a source of ignition

(facility conforming to NEC Class 1, Group D is not a source of ignition)? X

282. .171 (a) Does the compressor station have adequate fire protection facilities? If fire pumps are used,

they must not be affected by the ESD system. X

283. (b)

Do the compressor station prime movers (other than electrical movers) have over-speed

shutdown? X

284. (c)

Do the compressor units alarm or shutdown in the event of inadequate cooling or lubrication

of the unit(s)? X

285. (d)

Are the gas compressor units equipped to automatically stop fuel flow and vent the engine if

the engine is stopped for any reason? X

286. (e) Are the mufflers equipped with vents to vent any trapped gas? X

287. .173 Is each compressor station building adequately ventilated? X

288. .457 Is all buried piping cathodically protected? X

289. .481 Atmospheric corrosion of aboveground facilities X

290. .603

Does the operator have procedures for the start-up and shut-down of the station and/or

compressor units? X

291. Are facility maps current/up-to-date? X

292. .615 Emergency Plan for the station on site? X

293. .619 Review pressure recording charts and/or SCADA X

294. .707 Markers X

295. .731 Overpressure protection – relief’s or shutdowns X

296. .735

Are combustible materials in quantities exceeding normal daily usage, stored a safe distance

from the compressor building? X

Attachment 1







S U N/A N/C

297.

Is aboveground oil or gasoline storage tanks protected in accordance with NFPA standard

No. 30? X

298. .736 Gas detection – location X

Comments:


Documents

Utilities and Transportation Commission Standard …...Randy Bareither Pipeline Safety Engineer 509-495-8716 Linda Burger Pipeline Integrity Program Manager 509-495-4423 Dylan Karaus